Combustion modification proves its worth

The contributions of NOx emissions from combustion systems to acid rain, photochemical smog and fine particulate in the atmosphere are widely recognised. Accordingly, many of the developed nations have implemented a complex series of regulations which limit NOx emissions from combustion systems. Recently, the US EPA issued a directive, with a September deadline, for State Implementation Plans (the “SIP Call”) to be submitted by 22 northern and eastern states for deep NOx control, and defended it successfully in the US Court of Appeals against petitions from the states themselves and industry groups. Unless the case goes to the Supreme Court, 19 State authorities now have until October to submit plans that must be implemented by May 2003.

Combustion modification is generally the lowest cost NOx control method available, in particular retrofitting low NOx burners, and they have been retrofitted to many utility boilers. However, low NOx burners cannot be applied to all types of combustion systems and seldom achieve the NOx reductions required by the latest SIP Call requirements. Low NOx burners alone will not be capable of meeting all requirements owing to unavailability of suitable designs (such as for cyclone-fired units), performance problems with low NOx burners (such as carbon loss or tube wall wastage), or insufficient NOx reduction capability to meet CAA Title I requirements.

Low NOx burners

Fitting low NOx burners is usually the first modification. GE EER burner development work has shown that NOx can be reduced by controlling the rate of fuel/air mixing, particularly the premixing which can occur at the base of the flame as the primary pulverised coal/air stream entrains secondary combustion air.

FlamemastEER™

FlamemastEER (Figure 1) resulted from a joint development programme in 1987 of GE EER and two Danish companies - Elkraft Power Company, and Burmeister & Wain Energi (BWE), – to develop a high performance low NOx burner for European applications. The burner was based on existing BWE mechanical designs and performed well both in pilot scale tests and in full scale European retrofits. Subsequently, GE EER adapted the burner design for US boilers.

The burner has been designed to minimise the need for moving parts. Those parts which do move, slide axially, eliminating complex linkages and gears. The secondary and tertiary swirl control vanes, called turbolators, move axially within conical passages in the burner. As the turbolators are moved toward the narrow end of the cone more air passes through the vanes increasing swirl. As the turbolator is moved in the opposite direction, the air follows the path of least resistance and bypasses the vanes reducing swirl. The amount of combustion air entering each burner is controlled by a sliding ring damper. Similarly, the split between secondary and tertiary (outer zone) air is controlled by a second ring damper. The parts of the burner subjected to a high heat flux are fabricated from a high strength, heat resistant alloy.

The controls on the secondary and tertiary air allow a high degree of flame shape control. The flame length can be adjusted on line; flame shaping allows NOx emissions to be minimised depending on site specific constraints. The coal nozzle is sized to produce a primary air/coal velocity which controls the rate of secondary air entrainment. The nozzle tip includes a proprietary flame holder which is a key component and anchors the base of the flame in the burner exit. This minimises premixing of the primary air/coal with secondary air prior to the flame ignition point, and results in rapid devolatilisation of the coal and liberation of fuel nitrogen in a low excess air environment.

Short windbox model

GE EER discovered several applications where the existing windbox depth was only 2-4 feet. For this application GE EER developed a burner with a more conventional register to generate the swirl.

This design has been installed on four small wall fired boilers. Each boiler has four burners and very short windboxes. The performance has been good with all units operating below 0.46 lb/million Btu NOx emissions and with no flame impingement problems. This style has also been installed on four wall fired 625 000 lb/h units. Each of these boilers has nine burners, with the lower six burners closely spaced similar to a cell configuration. Results have been good with NOx emissions below 0.43 lb/million Btu and LOI less than 4 per cent on both high and low sulphur coals.

Fixed vane model

Owing to the harsh environment that a coal fired low NOx burner must endure, the best design has the fewest number of moving parts. And those parts that do move, should have a simple axial movement. That is the design philosophy of the fixed vane model. The swirl vanes are fixed. There are openings before and after the swirl vanes where the combustion air enters the burner. By controlling the introduction of air, the swirl and flame shape can be adjusted. The air is controlled by a sliding damper. The shapes of the air openings are determined from isothermal modelling and the design is based on equal air flow regardless of swirl. This burner design does require a deep windbox and the pulverisers in service should operate at equal feed rates.

The most recent installation was on a 632 MWe opposed wall fired unit with 49 burners, the new burner replacing the original dual register burners. Flame stability has been enhanced and NOx emissions have been reduced to less than 0.46 lb/million Btu.

Burner modifications

One key conclusion from EER’s low NOx burner development work is that the NOx reduction is a result of the control of fuel/air mixing, not necessarily the actual burner hardware. EER has achieved low NOx levels using a variety of burner hardware components, including various types of secondary air registers, central and annular coal nozzles, and a range of burner throat geometries and burner array spacing. This suggests that rather than completely replacing a burner, it may be possible to modify a conventional circular burner to effectively control fuel air mixing. This is the basis of EER’s low NOx burner combustion modification approach. Over the last four years, EER has carried out low NOx burner combustion modifications on twelve utility boilers with burners manufactured by Babcock and Wilcox, ABB/Combustion Engineering, Foster Wheeler and Phoenix, in sizes from 17 to 900 MW.

Design and performance

The modifications performed on each project vary widely. Preliminary evaluations provide a projection of potential NOx reduction. The next step is usually a windbox inspection of the existing burners to determine if analytical modelling is required. This may include isothermal flow testing of a burner mock up. EER then designs the specific hardware modifications, generally limited to the coal nozzle tip and the size and shape of the secondary air passage. Typically the coal pipe would be modified to adapt the primary velocity to the desired level consistent with mill operation and the available primary air/coal ratio. A flame stabiliser would be added to the end of the coal pipe, and a secondary air separation sleeve introduced to provide air staging. Control of the air distribution between the new secondary and tertiary air zones would be achieved by means of a sliding ring damper, and control of total air flow and swirl by means of the existing register. Generally no changes are made to the windbox, registers or pressure parts.

Units addressed to date have included cell burner units, single wall and opposed fired units, and unit sizes ranging from 17 MW to 868 MW as illustrated in Table 1. NOx reductions have ranged from 20 per cent to more than 60 per cent, with the lower percentage reductions being associated with smaller units already retrofitted with first generation low NOx burners, and the higher percentage reductions units with high intensity burners giving high initial NOx levels.

Experience with other operational factors has also generally been good, but (as with any burner low NOx retrofit) potential impacts on the emission of CO and fly ash LOI are of concern. To date, experience with CO emissions has been favourable, with final CO levels generally below 50 ppm. Experiences with changes in LOI have however been variable, and have depended on parameters such as coal type and the size and firing configuration of the unit.

Reburn technology

Reburn uses staged combustion to reduce NOx. During reburn (Figure 2) NOx is reduced by reaction with hydrocarbon fuel fragments. In application, no physical changes to the main burners or cyclones are required. The fuel input to the burners is simply reduced and the burners are operated with the lowest excess air commensurate with acceptable lower furnace performance considering such factors as flame stability, carbon loss, ash deposition, and wall corrosion.

The reburn fuel is injected above the main combustion zone to produce a slightly fuel rich “reburn zone” where most of the NOx reduction occurs. Maximum NOx reduction performance is typically achieved with the reburn zone operating around 90 per cent theoretical air. Above the reburn zone, overfire air is usually injected to complete combustion of any unburned fuel fragments.

Reburn technology offers the very attractive advantage of being able to operate over a wide range of NOx control capability. A system can literally be “ramped” from relatively low levels of control (25-30 per cent) using the overfire air system without any reburn fuel, to nearly 70 per cent control as reburn fuel is added. So the user can fine tune to meet regulatory requirements at the lowest possible cost.

Firing configuration

Because reburn system retrofits do not require modifications to the existing main combustion system, they can be applied to virtually any combustion system. Applications involving hot furnaces and high baseline NOx are attractive since both enhance the NOx reduction reactions.

Reburn can be applied to combustion systems fired with any fuel. For any given boiler load, the firing rate through the main fuel burners is reduced in proportion to the reburn fuel quantity to maintain constant boiler heat input. The lower firing rate reduces NOx emissions and may relieve problems with pulveriser capacity, fineness, combustion problems, opacity levels, etc.

Furnace volume

There must be sufficient space above the burners or cyclones to install the reburn components and to produce adequate residence time in the reburn and burnout zones. By designing the gas and overfire air injectors for rapid mixing, space requirements can be minimised. NOx reduction as deep as 70 per cent was achieved in a cyclone application with effective reburn zone residence time of only 0.25 seconds.

Reburn fuel injectors

The reburn fuel injectors should be located close to the upper firing elevation but with enough space to avoid interference from the main burn. For maximum NOx reduction a rapid mix with the furnace gases is necessary. Since the amount of fuel injected is small compared to the furnace gas flow rate, achieving penetration and rapid mixing is a challenge, especially for larger furnaces. They can be enhanced by increasing the momentum of the injected stream via a carrier gas or high velocity injection.

It is desirable to minimise (and ideally eliminate) any oxygen introduced with the reburn fuel. The oxygen must be consumed by additional fuel to achieve the desired slightly fuel rich reburn zone stoichiometry. GE EER’s current natural gas reburn design utilises the pressure of the gas supply to produce high velocity jets, eliminating all injected oxygen and thus minimising the gas requirement.

Overfire air ports

Most of the main fuel char oxidation occurs in the oxygen rich primary combustion zone. The burnout zone completes combustion of any residual and reburn fuel fragments (primarily CO). The overfire air ports must be positioned to balance the NOx reduction performance of the reburn zone with final combustion in the burnout zone. This trade off is optimised by locating the overfire air ports substantially higher in the furnace than for conventional overfire air applications but well beneath the entrance to the convective surfaces.

Overfire air design considerations

The overfire air ports need to be designed for rapid and complete mixing. GE EER utilises dual concentric overfire air ports with swirl control. This arrangement allows the overfire air injection process to be controlled over a wide range of conditions to optimise burnout, a key advantage where the reburn fuel flow rate is controlled to vary NOx reduction performance and to minimise fuel use.

Reburn retrofit applications

Table 2 summarises GE EER’s reburn retrofit project experience. All major firing configurations are included; tangential, wall and cyclone firing boilers with both wet and dry bottom operation, with coal and gas as the main fuels and coal, oil, and natural gas as reburn fuels.

Allen units 1-3

In April 1997, Tennessee Valley Authority (TVA) awarded GE EER a contract to supply a gas reburn system for unit 1 of the Allen fossil station, with options for units 2 and 3; these units are identical 330 MW cyclone units firing a blend of bituminous and Western coals in seven cyclone furnaces per boiler. TVA is using the NOx reduction to comply with the Title IV cyclone NOx limit of 0.86 lb/million Btu. The aim is to achieve this NOx limit while minimising the gas injection rate. TVA tests have shown that the baseline NOx varies substantially as the coal blend varies.

The NOx limit can be maintained by varying the gas injection rate as the coal blend composition changes. The gas reburn installation on unit 1 has been completed.

The reburn system injectors were designed to inject natural gas and overfire air into the boiler under automatic control over the load range of 150 to 300 MWe. The natural gas injectors were positioned on all four walls of the furnace above the cyclones. This arrangement provides near uniform dispersion of the reburn fuel in this highly complex furnace flow field. The overfire air (OFA) system injects heated secondary combustion air from the air heater outlet. It can inject up to 25 per cent of the total combustion air, at peak steam flow, without the installation of any additional fans. The OFA is injected through four injection ports on the front wall and four on the rear wall of the furnace.

The reburn equipment was installed in spring 1998 and a series of tests conducted to establish the optimum operating conditions prior to conducting compliance testing. As the gas injection rate is increased, NOx emissions decrease monotonically. The maximum NOx reduction was over 65 per cent; the 0.86 lb/million Btu Title IV NOx limit was met with about 7 per cent gas. The compliance testing further demonstrated that performance guarantees for CO emissions and carbon-in-ash were simultaneously met.

Tests at Allen 1 using overfire air only (no gas) have shown that this in able to meet current NOx control requirements. Therefore, TVA elected to install only the overfire component on units 2 and 3. This work has also been completed.

Crane units 1-2

In 1997, Baltimore Gas and Electric (BGE) awarded GE EER two contracts to supply engineering, material, and construction/start-up support for a gas reburn system retrofit to their Crane Station units 1 and 2 near Baltimore, Maryland. These are similar 200 MW units firing bituminous coal through four cyclones each. BGE selected gas reburn as the most cost-effective control technology to comply with Title I NOx limits system wide.

The reburn systems for both boilers were designed to operate with up to 25 per cent heat input from natural gas over the range of 100 to 200 MWe. They utilise second generation reburn technology; i.e., no flue gas recirculation is required as a carrier medium when injecting the natural gas into the boiler. This reduces the capital cost of the equipment and minimises the reburn fuel requirement. Four OFA injectors were installed on both the front and rear walls. No overfire air booster fans were required since the combustion air pressures were sufficiently high to produce the required air injection velocities. Four gas injector assemblies were installed on both the front and rear walls. Because of concern about slagging, GE EER’s “self cleaning” gas injector design was supplied.

The systems were placed in service in May 1999 and operated during the ozone season from May until September. During optimisation testing of the reburn system on unit 2, the NOx emissions were reduced from a baseline 1.5-2.0 lb/million Btu to 0.70 lb/million Btu with 18 per cent gas heat input and to 0.52 lb/million Btu with 26.5 per cent gas heat input. Unit 1 performance displayed similar results.

Edge Moor unit 4

The utility Conectiv contracted with GE EER for the installation of a gas reburn system for their Edge Moor unit 4, a 160 MW tangentially-fired boiler. The reburn system became operational during the 1999 ozone season.

Edge Moor 4 has been retrofitted with an International Combustion low NOx firing system which includes flame attached nozzles and close coupled overfire air (CCOFA). GE EER designed the reburn system to take full advantage of these components. In particular, the flow rate of air to the CCOFA will allow the stoichiometric ratio of the flue gas entering the reburn zone to be tuned independent of the burner stoichiometric ratio for additional optimisation flexibility. The reburn system is capable of operating in several modes: two stages of overfire air (CCOFA plus the separated OFA from the reburn system) for modest NOx control, stratified reburning for maximum NOx reduction per unit gas injected at low gas injection rates, and full reburning for maximum NOx reduction at higher gas injection rates.

Testing took place in July 1999 and showed that NOx was reduced from a baseline level of 0.31 lb/million Btu to 0.16 lb/million Btu at 23.5 per cent gas heat input, a reduction of 48 per cent (see Figure 3). CO emissions were maintained below 50 ppm.

In progress

In October 1998 GE EER contracted to supply a gas reburn system for the Allegheny Power Hatfield unit 2, a nominally 595 MWe gross, supercritical, opposed wall fired boiler manufactured by Babcock and Wilcox. Installation was completed in early spring 2000. The gas injection system consists of twelve injectors, the overfire air injection system of fourteen injectors. Booster fans are utilised as part of the overfire system to provide significantly more operating flexibility than could be achieved with the available windbox pressure (<2.5in W.G.). Performance projections indicate that NOx will be reduced from a baseline of 0.46 lb/million Btu to 0.17 lb/million Btu with 18.6 per cent gas heat input.

In May 1999 GE EER provided a natural gas reburn systems for Potomac Electric Power Company’s Chalk Point units 1 and 2. Installation was completed in May 2000 and testing was expected to be finished by the end of July. The boilers are Babcock and Wilcox 355 MWe opposed-wall fired units with Riley low NOx burners. Baseline NOx emissions at MCR were reported as ranging between 0.7 and 1.1 lb/million Btu. GE EER has predicted that the NOx can be reduced to 0.34 lb/million Btu with 15 per cent gas heat input, a reduction of 60 per cent. Work is also in progress on three coal reburn applications. Two are 800 MW tangentially fired utility boilers and the third is a wall fired industrial boiler.

Performance summary

Figure 4 summarises GE EER’s reburn NOx control database. Data are shown from eight completed reburn retrofits and projections are shown for two applications where the retrofits are in progress. Two of the completed retrofits, one wall-fired and one tangentially-fired design, were tested with both gas and coal as primary fuels and thus appear twice. The format allows baseline NOx emissions, reburn NOx emissions, and reburn NOx reduction to be readily compared. Each line shows the full range of possible NOx control and represents the potential performance of reburn on a specific unit. The intercept at 0.0 per cent NOx reduction corresponds to the baseline NOx emission. The actual reburn system performance under various operating conditions is shown as data points on the line.

Costs

In evaluating the cost of NOx control via reburning, both capital and operating cost components must be considered. The retrofit capital cost of a reburn project is site specific. The nominal turnkey cost for a gas reburn system retrofitted to a 300 MW unit is approximately $10-15/kW. The operating cost for reburn is near zero except for the differential cost of the reburning fuel over the main boiler fuel. For coal reburning, the differential cost is zero. Reburn fuels such as oil or natural gas are generally more costly than the main fuel but part of the differential cost may be offset by SO2 emission reductions, reductions in pulveriser power and reductions in ash.

Reburn with other fuels

As well as natural gas, GE EER is also working on alternate reburn fuels including micronised coal, Orimulsion®, A-55 Clean Fuels, biomass and others. While the reburn data base for these fuels is not as extensive as that for reburn, these fuels have several potential benefits which may make them attractive in a wide range of NOx control applications.

Micronised coal reburning typically achieves somewhat less NOx reduction than reburn; however there is no reburning fuel cost differential and this significantly reduces the operating cost compared to reburn. Retrofit costs for micronised coal reburning are higher than reburn principally due to the cost of the coal preparation and injection components. GE EER has retrofitted a large (about 45 MW) Eastman Kodak industrial boiler to micronised coal reburning. The baseline NOx was 1.3 lb/million Btu. NOx less than 0.6 lb/million Btu was achieved at about 16 per cent reburn fuel.

Orimulsion® is an emulsified bitumen fuel produced in Venezuela. It has firing characteristics similar to fuel oil. In Orimulsion reburn, the fuel is atomised and injected along with a carrier gas to promote mixing and dispersion. Retrofit costs for Orimulsion® reburn are higher than reburn, due principally to the carrier gas system, and less than micronised coal reburn. GE EER has conducted extensive pilot scale tests and a full scale demonstration. The NOx levels achieved were nearly as low as those achieved with natural gas reburn.

Ongoing development

The development of reburn technology is continuing. Improvements involve the integration of reburn with post-combustion flue gas treatment technologies and with the injection of additives to promote the NOx reduction reactions.

Potential for reburn technology

Reburn has been, or is being, applied to twelve boilers covering the range of 33 to 596 MWe capacity with tangential, wall and cyclone-firing configurations operating with coal and gas both as the primary fuels and as the reburn fuels. NOx emissions reductions of 58 to 77 per cent have been achieved. No significant operational or durability problems have been encountered. These results demonstrate the potential for reburn to meet a wide range of CAA requirements and, in particular, can be combined with low NOx burners, SNCR, and in-duct SCR to meet recently proposed SIP Call requirements for a large proportion of the boiler population.